Expro Ltd

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited condensed consolidated financial statements and the related notes thereto included elsewhere in this Form 10-Q and the audited consolidated financial statements and notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report.

 

This section contains forward-looking statements that are based on management’s current expectations, estimates and projections about our business and operations, and involve risks and uncertainties. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements because of various factors, including those described in the sections titled “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” of this Form 10-Q and our Annual Report.

 

Overview of Business

 

Working for clients across the entire well life cycle, we are a leading provider of energy services, offering cost-effective, innovative solutions and what we consider to be best-in-class safety and service quality. With roots dating to 1938, we have approximately 7,000 employees and provide services and solutions to leading exploration and production companies in both onshore and offshore environments in over 60 countries. Our extensive portfolio of capabilities spans well construction, well flow management, subsea well access, and well intervention and integrity solutions.

 

 

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Our well construction products and services support customers’ new wellbore drilling, wellbore completion and recompletion, and wellbore plug and abandonment requirements. We offer advanced technology solutions in tubular running services, tubular products, cementing, drilling and wellbore cleanup. With a focus on innovation, we are continuing to advance the way wells are constructed by optimizing process efficiency on the rig floor, developing new methods to handle and install tubulars, and mitigating well integrity risks. We believe we are a market leader in deepwater tubular running services and solutions. In recent years, we have added a range of lower-risk, open water cementing solutions. We also offer a range of performance drilling tools designed to mitigate risk and optimize drilling efficiency, including proprietary downhole circulation tools and hydraulic pipe recovery systems.

 

Well Management

Our well management offerings consist of well flow management, subsea well access and well intervention and integrity services:

 

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Well flow management: We gather valuable well and reservoir data, with a particular focus on well-site safety and environmental impact. We provide global, comprehensive well flow management systems for the safe production, measurement and sampling of hydrocarbons from a well, including well testing during the exploration and appraisal phase of a new field; flowback and clean-up of a new well prior to production; and in-line testing of a well during its production life. We also provide early production facilities to accelerate production; production enhancement packages to enhance reservoir recovery rates through the realization of production that was previously locked within the reservoir; flare reduction and other emissions management solutions; and metering and other well surveillance technologies to monitor and measure flow and other characteristics of wells.

 

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Subsea well access: With nearly 50 years of experience providing a wide range of fit-for-purpose subsea well access solutions, our technology aims to provide safe well access and optimized production throughout the lifecycle of the well. We provide what we believe to be the most reliable, efficient and cost-effective subsea well access systems for exploration and appraisal, development, intervention and abandonment, including an extensive portfolio of standard and bespoke Subsea Test Tree Assemblies (“SSTA”) and a range motion-compensating and other surface handling equipment. We also provide services and solutions through a rig-deployed Intervention Riser System (“IRS”) utilizing rigs owned by a third party and have capabilities for vessel-deployed services. In addition, we provide systems integration and project management services.

 

 

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Well intervention and integrity: We provide well intervention solutions to acquire and interpret well data, maintain and restore well bore integrity and improve production. In addition to our extensive fleet of mechanical and cased hole wireline units, we have recently introduced and acquired a number of cost-effective, innovative well intervention services, including CoilHose™, a lightweight, small-footprint solution for wellbore lifting, cleaning and chemical treatments; Octopoda™, for fluid treatments in wellbore annuli; Galea™, an autonomous well intervention solution; and expandable casing patches designed to repair damaged production casing or isolate existing perforations prior to refracturing a well (a so called “patch and perf”). We also possess several other distinct technical capabilities, including fiber optic-enabled data acquisition and interpretation services, non-intrusive metering technologies and wireless telemetry systems for reservoir monitoring.

 

We operate a global business and have a diverse and relatively stable customer base that is comprised of national oil companies (“NOC”), international oil companies (“IOC”), independent exploration and production companies (“Independents”) and service partners. We have strong relationships with a number of the world’s largest NOCs and IOCs, some of which have been our customers for decades. We are dedicated to safely and sustainably delivering maximum value to our customers.

 

We organize and manage our operations on a geographical basis. Our reporting structure and the key financial information used by our management team is organized around our four operating segments: (i) North and Latin America (“NLA”), (ii) Europe and Sub-Saharan Africa (“ESSA”), (iii) Middle East and North Africa (“MENA”) and (iv) Asia-Pacific (“APAC”).

 

How We Generate Our Revenue

 

Our revenue is derived primarily from providing services in well construction, well flow management, subsea well access and well intervention and integrity to operators globally. Our revenue includes equipment service charges, personnel charges, run charges and consumables. Some of our contracts allow us to charge for additional deliverables, such as the costs of mobilization of people and equipment and customer specific engineering costs associated with a project. We also procure products and services on behalf of our customers that are provided by third parties for which we are reimbursed with a mark-up or in connection with an integrated services contract. We also design, manufacture and sell equipment, which is typically done in connection with a related operations and maintenance arrangement with a particular customer. In addition, we also generate revenue from the sale of certain well construction products.

 

Commodity Prices and Market Conditions

 

Commodity Prices 

 

According to the Energy Information Administration (“EIA”), average daily oil demand declined by 1.1 million b/d in the first quarter of 2026 compared with the previous quarter. Demand was also modestly lower – by 0.4 million b/d – compared to the full-year 2025 average, although, consumption remained higher than levels recorded in the first quarter of 2025. Global liquids demand is expected to grow by 0.6 million b/d in 2026 compared with 2025, with a further increase of 1.6 million b/d anticipated in 2027.

 

Brent crude prices rose sharply during the quarter following the onset of military action in the Middle East at the end of February. The resultant effective closure of the Strait of Hormuz, a critical petroleum export route, and the subsequent production shut-ins drove a rapid tightening of supply. Brent averaged $67/bbl in January before rising to an average of $103/bbl in March, with daily prices spiking near $128/bbl on April 2. This volatility was further evidenced following the April 7 ceasefire announcement, when Brent price dropped back below $100/bbl. The U.S. subsequently announced a blockade of Iranian ports and Brent prices have increased back to approximately $100/bbl and remain volatile.

 

Market Conditions

 

Prior to the outbreak of conflict in the Middle East, the global oil market in 2026 had been expected to remain oversupplied, with inventories building and prices declining steadily. The onset of hostilities has rapidly altered these dynamics. Significant volumes of production across the region have been shut-in, creating near-term market tightness and heightened price volatility. Although a two-week ceasefire was announced on April 7, disruptions to global oil markets are expected to persist through 2026. The resumption of production and the clearance of backlogs through the Strait of Hormuz will take time, and ongoing geopolitical uncertainty continues to support elevated prices. Against this backdrop, hydrocarbon demand continues to grow in the near to medium term, while energy security remains a key strategic priority for governments and operators, supporting continued investment across the industry. Over the longer term, geopolitical disruption events such as the current Middle East crisis could result in structural shifts towards greater energy independence and diversification of supply, although such transitions are expected to evolve gradually given the continued central role of hydrocarbons in the global energy system.

 

 

There are a number of market factors that have had, and may continue to have, an effect on our business, including:

 

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The market for energy services and our business are substantially dependent on the price of oil and, to a lesser extent, the regional price of gas, which are both driven by market supply and demand. Changes in oil and gas prices impact customer willingness to spend on exploration and appraisal, development, production, and abandonment activities. The extent of the impact of a change in oil and gas prices on these activities varies extensively between geographic regions, types of customers, types of activities and the financial returns of individual projects.

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Activity related to gas and liquified natural gas (“LNG”) production (and associated asset development) continues to grow as demand outpaces supply and long-term energy security remains an over-increasing priority. More broadly, the net-zero targets of many nations requires a transition to lower-carbon sources such as natural gas and LNG, resulting in increased investment in the production of the fuels.

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International and offshore activity drives the majority growth throughout 2026. We also see an increased demand for services related to brownfield and production enhancement and infield development programs as operators strive to maximize their previous investments and maintain production with a lower carbon footprint. In addition, we have seen an increase in demand for production optimization technologies, especially in support of gas and LNG developments.

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Expro remains selective in pursuing low-carbon opportunities that support operators’ drive for increased sustainability in their hydrocarbon production, including early-stage carbon capture and storage and flare reduction. While the broader trend toward decarbonization continues, our customers focus remains on energy security and returns driven by their core hydrocarbon businesses.

 

Outlook

 

The EIA states global liquids demand in 2026 is expected to average 104.6 million b/d, representing growth of 0.6 million b/d year-on-year. This is a downward revision from earlier expectations of 1.2 million b/d of growth. The revision reflects government-led fuel conservation initiatives, fuel shortages, and reduced refined product exports, particularly in Asia, which is more dependent on Middle Eastern supply. Demand is expected to rebound in 2027 as supply flows normalize later in 2026, with consumption forecast to rise by 1.6 million b/d to an average of 106.2 million b/d.

 

The EIA forecasts global liquids production to average 104.3 million b/d in 2026, down 2.0 million b/d from 2025. The decline reflects ongoing constraints on movements through the Strait of Hormuz, with the impact of the negotiated two-week ceasefire yet to be fully established. In March, Iraq, Saudi Arabia, Kuwait, the UAE, Qatar and Bahrain collectively shut in an estimated 7.5 million b/d of crude oil production, with shut-ins expected to rise to 9.1 million b/d in April. The EIA’s base case assumes the conflict does not persist beyond April, with traffic through the Strait gradually resuming thereafter. Under this assumption, shut-ins are forecast to fall to 6.7 million b/d in May and return close to pre-conflict levels by late 2026. Earlier assumptions had anticipated a one-month disruption to oil flows, peaking in March, with sufficient market supply keeping Brent below a $100/bbl monthly average if the conflict was resolved quickly. However, the prolonged closure of the Strait has driven sharp inventory drawdowns and higher shut-in volumes, prompting upward revisions to price forecasts. The potential for further escalation, including attacks on energy infrastructure, and uncertainty around the duration of disruptions are expected to sustain a significant risk premium in oil prices. Even once flows through the Strait resume, the normalization of tanker routes and trade flows is likely to be gradual, supporting elevated prices throughout this year and into 2027.

 

Based on these factors, the EIA expects Brent crude prices to rise from an average of $81/bbl in the first quarter of 2026 to a peak of $115/bbl, before easing to an average of $88/bbl by the fourth quarter. This implies a full-year 2026 average Brent price of $96/bbl.

 

Following publication of the EIA forecast, a ceasefire was announced on April 7, prompting a near-term easing in oil prices and a rally in equity markets. Brent prices declined by approximately $15/bbl. As a result, Rystad Energy lowered its 2026 average Brent forecast to approximately $87/bbl as the immediate panic premium eased. However, uncertainty remains high, with the U.S. announcing a blockade of Iranian ports and fundamental disagreements unresolved and the ceasefire fragile. Price risk remains skewed to the upside amid continued volatility with prices not expected to return to pre-conflict levels in the near term, as physical market tightness, supply chain disruptions and the gradual normalization of flows through the Strait of Hormuz continue to support a residual risk premium.

 

 

While operators remain cautious about committing to long-term investments in a volatile environment, oil prices sustained above the pre-conflict $65/bbl to $70/bbl floor are expected to support continued upstream spending. Investment is driven by both enduring hydrocarbon demand and the increasing emphasis on energy security, providing a supportive demand environment for Expro’s products and services.

 

In parallel, a supportive oil market and robust international gas prices are expected to drive increased activity, particularly in LNG-linked developments, through 2026. The EIA forecasts Henry Hub prices to average $3.67/MMBtu in 2026, up from $3.53/MMBtu in 2025, before easing slightly to $3.59/MMBtu in 2027. Higher expected prices reflect weather-driven volatility earlier in the year, strong LNG feedgas demand and slower production growth. U.S. gas prices have been largely insulated from Middle East disruptions due to high LNG export utilization, limiting the ability to export incremental volumes in the near term.

 

Rystad Energy’s March 5 outlook maintained largely unchanged gas price expectations for 2026, but subsequent updates have factored in escalating geopolitical risks. In its March 13 forecast, Rystad raised 2026 price expectations for TTF and Northeast Asian spot markets to $13.50/MMBtu and $14.00/MMBtu, respectively, with intra-year trading reaching around $25.00/MMBtu. The effective closure of the Strait of Hormuz, combined with infrastructure attacks, has resulted in the shutdown of significant LNG production capacity in Qatar and the UAE—equivalent to around 20% of global supply. Rystad’s base case assumes the Strait reopens in April with flows normalizing by May. Despite the relatively modest volume disruption to date, European and Asian gas prices have surged alongside oil prices, as oil-linked fuels remain the primary alternative for Asian buyers. As a result, natural gas continues to present ample opportunity for Expro as operators invest to support long-term energy diversification.

 

The conflict has reinforced the focus on energy security, accelerating operator interest in supply resilience and geographic diversification—trends expected to shape investment behavior through 2026 and beyond. Capital discipline and selective project sanctioning remain central, with offshore and deepwater developments continuing to offer attractive, lower-risk growth opportunities. These dynamics underpin demand for Expro’s well construction, well flow management and subsea well access services.

 

At the same time, brownfield optimization remains a growing priority as operators seek to enhance production from existing assets while minimizing capital risk. This creates opportunities across Expro’s well intervention and integrity, production optimization and digital product portfolios.

 

Overall, Expro expects a balanced 2026, characterized by early-year volatility linked to Middle East disruptions but underpinned by resilient deepwater and LNG-related activity. Activity levels are expected to strengthen in the second half of the year. Expro’s strong offshore and international positioning, combined with its production optimization capabilities, leaves the company well placed to manage near-term uncertainty and benefit from a gradual market recovery through 2026 and beyond.

 

The following provides an outlook for 2026 by our reporting segments based on data from Spears and Associates Inc:

 

NLA: Despite the unexpected spike in oil prices that has emerged since the start of fighting in the Persian Gulf, little change is anticipated to operators’ 2026 drilling, completion and production plans as they have been conditioned and incentivized to resist the urge to adjust planned capex in response to short-term price swings. Overall, North American drilling activity (>95% of which is land based) is forecast to hold steady in 2026 to average 561 active rigs, accounting for a total of around 14,700 wells (down 4% from 2025). Completion activity in the region is expected to slow by 3% in 2026, totaling about 11,300 frac jobs for the year. The current trend is expected to remain in place with 2026 seeing gains in the gas-centric rig count, while the oil rig count is projected to fall 8% year-over-year to an average of 408 active units. Central and South American rig activity is projected to increase by 5% compared to 2025, to average 141 active rigs, accounting for a total of almost 1,850 new wells. Onshore drilling in the region is forecast to increase 5% in 2026 to an average of 105 active land rigs drilling 1,625 new wells, while offshore activity is projected to grow by 3%, averaging 36 active rigs totaling over 200 new wells drilled. According to Westwood Energy, approximately 23%, or 15, of the world’s projected 65 high-impact wells are expected to be drilled in South America in 2026, with key activities concentrated in the Suriname-Guyana basin and Brazil’s Santos and Campos basins. E&P activity in the region is characterized by large offshore deepwater plays (Brazil, Guyana, Suriname) and the development of major unconventional shale resources in Argentina. The region is attracting significant investment due to low breakeven prices and large deepwater discoveries comprised of high-quality, low sulfur crude.

 

 

ESSA: European drilling activity is expected to drop 4% in 2026 to an average of 93 active rigs accounting for a total of about 725 new wells. Onshore drilling in Europe is forecast to average 69 active rigs, down 3%, accounting for about 460 new wells, while offshore drilling is projected to decline by 8% in 2026, averaging 24 active rigs accounting for about 260 new wells. The European upstream sector is a mature one, concentrated in North Sea (Norway and the UK), Romania and the Netherlands. It is defined by high-cost offshore operations, stringent safety and environmental regulations, and a shift toward energy security and decarbonization. Operations increasingly prioritize capital discipline and extracting value from mature fields instead of aggressive volume growth. Norway continues to see strong investment and exploration dominance, while the UK sector faces more rapid decline and political uncertainty regarding new licenses. In all, new field development is pivoting away from the Noth Sea toward projects in the Black Sea and East Mediterranean. African drilling (including North Africa) is projected to grow by 2% in 2026 compared to 2025 to an average of 126 active rigs, accounting for a total of almost 950 new wells. Onshore drilling is forecast to slip by 2% this year to an average of 106 active land rigs, accounting for about 730 new wells, while offshore activity is projected to jump 33% in 2026, averaging 20 active rigs drilling over 200 new wells. Africa is forecast to lead global high-impact drilling in 2026, with roughly 40% of the world’s planned high-stakes wells, particularly Namibia, West Africa and frontier basins, with 17 to 19 high-impact wells expected to be drilled. African operators account for over 7% of global oil output, while countries in the region contain over 5% of proven global natural gas reserves. Activity is increasing focused on natural gas aimed at both domestic industrialization and exporting to Europe and Asia. However, African oil and gas assets are on average 15 to 20% more expensive to develop and 70 to 80% more carbon-intensive than global averages.

 

MENA: The forecast assumes the current conflict in the Persian Gulf does not result in extended disruption to oilfield equipment supply chains in the region, however, the forecast was published on March 5, prior to continued escalation in the region and the duration of the crisis poses a major uncertainty to the outlook. Middle Eastern drilling activity is now expected to increase by 3% in 2026 to an average of 520 active rigs accounting for a total of over 3,000 new wells. Onshore drilling in the region is projected to grow by 3% to an average of 438 rigs drilling over 2,750 new wells, while offshore activity is forecast to hold steady at an average of 81 rigs, accounting for almost 270 new wells. It was estimated that at the start of the conflict oilfield equipment manufacturers and service firms in the region has sufficient inventory on hand to sustain drilling activity at its current levels for approximately 2 months, however, it has since been reported many rigs have paused drilling activity given the ongoing risk. Regional operators have been aggressively expanding natural gas production, both for export and to meet rapidly growing demand for power, industry and desalination, while also reducing domestic consumption of crude oil. Led by Qatar, Saudi Arabia, and the UAE, regional gas production is expected to reach 86 to 98 billion cubic feet per day by 2030, though this will likely be impacted by the recent Iranian attacks on energy infrastructure in the region.

 

APAC: Drilling activity in Asia-Pacific is forecast to average 187 active rigs in 2026, an increase of 4% compared to 2025, accounting for over 2,500 new wells drilled. India, Indonesia and Thailand are the three most active drillers in this geo-market. Onshore drilling in the region is forecast to increase by 3% this year, to an average of 135 active land rigs drilling over 1,700 new wells, while offshore activity is projected to grow by 8% to an average of 53 rigs totaling over 800 new wells. Driven by countries such as Malaysia, Indonesia, Thailand and Vietnam, the Asia-Pacific region is seeing a resurgence in investment from major international players alongside national oil companies. Offshore oil and gas development in Southeast Asia is projected to see an estimated $100 billion in offshore gas investments between 2024 and 2028. Energy security concerns, heightened by the ongoing Middle East conflict and rising demand for gas to power the region’s rapidly growing economies have prompted a number of explorers to focus on recent multi-trillion cubic feet gas discoveries in the regions’ Andaman basin with straddles the offshore areas of Indonesia, Thailand, Myanmar and India.

 

 

How We Evaluate Our Operations

 

We use a number of financial and operational measures to routinely analyze and evaluate the performance of our business, including Revenue and Adjusted EBITDA.

 

Revenue: We analyze our performance by comparing actual monthly revenue by operating segments and areas of capabilities to our internal projections for each month. Our revenue is primarily derived from well construction, well flow management, subsea well access and well intervention and integrity solutions.

 

Segment EBITDA: We use Segment EBITDA to assess the performance and compare the results of each segment with one another and consider budget-to-actual variances on a monthly basis. Segment EBITDA excludes non-cash charges and corporate transactions not related to the operating activities of our segments and allows more meaningful analysis of the trends and performance of our segments.

 

Adjusted EBITDA: We regularly evaluate our financial performance using Adjusted EBITDA. Our management believes Adjusted EBITDA is a useful financial performance measure as it excludes non-cash charges and other transactions not related to our core operating activities and allows more meaningful analysis of the trends and performance of our core operations.

 

Adjusted EBITDA is a non-GAAP financial measure. Please refer to the section titled “Non-GAAP Financial Measures” for a reconciliation of Adjusted EBITDA to net income (loss), the most directly comparable financial performance measure calculated and presented in accordance with GAAP.

 

Executive Overview

 

Three months ended March 31, 2026, compared to three months ended December 31, 2025

 

Certain highlights of our financial results include:

•	Revenue for the three months ended March 31, 2026, decreased by $14.6 million, or 3.8%, to $367.6 million, compared to $382.1 million for the three months ended December 31, 2025. The decrease in revenue was a result of lower activity in the MENA, ESSA and NLA segments, marginally offset by stronger performance in APAC. Revenue for our segments is discussed separately below under the heading “Operating Segment Results.”
•	We reported net loss for the three months ended March 31, 2026, of $1.0 million, a decrease of $6.8 million, or 117.9%, as compared to net income of $5.8 million for the three months ended December 31, 2025. Net loss margin was (0.3)% for the three months ended March 31, 2026 compared to net income margin of 1.5% for the three months ended December 31, 2025. The decrease was primarily reflected by a decrease in Adjusted EBITDA of $25.5 million, partially offset by lower severance and other expense of $6.7 million and lower depreciation and amortization expense of $8.4 million.
•	Adjusted EBITDA for the three months ended March 31, 2026, decreased by $25.5 million, or 28.8%, to $62.9 million from $88.4 million for the three months ended December 31, 2025. Adjusted EBITDA margin was 17.1% for the three months ended March 31, 2026, down compared to 23.1% for the three months ended December 31, 2025. The decrease in Adjusted EBITDA was primarily due to lower revenue and less favorable activity mix.
•	Net cash provided by operating activities for the three months ended March 31, 2026, was $25.3 million, as compared to net cash provided by operating activities of $57.1 million for the three months ended December 31, 2025, primarily driven by a decrease in Adjusted EBITDA and working capital movements.

 

 

Non-GAAP Financial Measures

 

We include in this Form 10-Q the non-GAAP financial measures Adjusted EBITDA and Adjusted EBITDA margin. We provide reconciliations of net income, the most directly comparable financial performance measure calculated and presented in accordance with GAAP, to Adjusted EBITDA.

 

Adjusted EBITDA and Adjusted EBITDA margin are used as supplemental financial measures by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others. These non-GAAP financial measures allow our management and others to assess our financial and operating performance as compared to those of other companies in our industry, without regard to the effects of our capital structure, asset base, items outside the control of management and other charges outside the normal course of business.

 

We define Adjusted EBITDA as net income (loss) adjusted for (a) income tax expense (benefit), (b) depreciation and amortization expense, (c) impairment expense, (d) severance and other expense, net, (e) stock-based compensation expense, (f) merger and integration expense, (g) gain on disposal of assets, (h) other income (expense), net, (i) interest and finance (income) expense, net and (j) foreign exchange (gain) loss. Adjusted EBITDA margin reflects our Adjusted EBITDA as a percentage of revenues.

 

Adjusted EBITDA and Adjusted EBITDA margin have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. As Adjusted EBITDA may be defined differently by other companies in our industry, our presentation of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

 

 

The following table presents a reconciliation of net income (loss) to Adjusted EBITDA for each of the three months presented (in thousands): 

 

	Three Months Ended
	March 31, 2026				December 31, 2025				March 31, 2025
Net (loss) income	$	(1,034	)		$	5,772			$	13,948
Income tax expense (benefits)	$	6,217			$	7,605			$	(1,716	)
Depreciation and amortization expense		45,395				53,774				45,421
Severance and other expense		3,226				9,952				6,082
Merger and integration expense		288				861				1,740
Other income, net (1)		(347	)			(188	)			(1,654	)
Stock-based compensation expense		7,274				7,689				6,968
Foreign exchange loss		339				463				1,988
Interest and finance expense, net		1,551				2,445				3,451
Adjusted EBITDA	$	62,909			$	88,373			$	76,228
Net (loss) income margin		(0.3	)%			1.5	%			3.6	%
Adjusted EBITDA margin		17.1	%			23.1	%			19.5	%

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(1)	Other income, net, is comprised of immaterial, unusual or infrequently occurring transactions which, in management’s view, do not provide useful measures of the underlying operating performance of the business.

 

 

Results of Operations

 

Operating Segment Results

 

We evaluate our business segment operating performance using segment revenue and Segment EBITDA, as described in Note 5 “Business segment reporting” in our consolidated financial statements. We believe Segment EBITDA is a useful operating performance measure as it excludes non-cash charges and other transactions not related to our core operating activities and corporate costs, and Segment EBITDA allows management to more meaningfully analyze the trends and performance of our core operations by segment as well as to make decisions regarding the allocation of resources to our segments.

 

The following table shows revenue by segment and revenue as a percentage of total revenue by segment for the periods presented (in thousands):

 

	Three Months Ended										Percentage
	March 31, 2026				December 31, 2025				March 31, 2025		March 31, 2026				December 31, 2025				March 31, 2025
NLA	$	128,183			$	130,305			$	134,278		34.9	%			34.1	%			34.4	%
ESSA		113,919				116,322				112,373		31.0	%			30.5	%			28.7	%
MENA		81,663				92,985				93,554		22.2	%			24.3	%			23.9	%
APAC		43,808				42,515				50,667		11.9	%			11.1	%			13.0	%
Total Revenue	$	367,573			$	382,127			$	390,872		100.0	%			100.0	%			100.0	%

 

 

The following table shows Segment EBITDA and Segment EBITDA margin by segment and a reconciliation to income before income taxes for the periods presented (in thousands):

 

	Three Months Ended											Segment EBITDA Margin
	March 31, 2026				December 31, 2025				March 31, 2025			March 31, 2026				December 31, 2025				March 31, 2025
NLA	$	25,937			$	31,795			$	30,386			20.2	%			24.4	%			22.6	%
ESSA		31,505				40,039				29,188			27.7	%			34.4	%			26.0	%
MENA		23,567				36,121				34,168			28.9	%			38.8	%			36.5	%
APAC		7,196				6,952				10,862			16.4	%			16.4	%			21.4	%
Total Segment EBITDA		88,205				114,907				104,604
Corporate costs (1)		(28,527	)			(30,372	)			(32,082	)
Equity in income of joint ventures		3,231				3,838				3,706
Depreciation and amortization expense		(45,395	)			(53,774	)			(45,421	)
Merger and integration expense		(288	)			(861	)			(1,740	)
Severance and other expense		(3,226	)			(9,952	)			(6,082	)
Stock-based compensation expense		(7,274	)			(7,689	)			(6,968	)
Foreign exchange loss		(339	)			(463	)			(1,988	)
Other income, net		347				188				1,654
Interest and finance expense, net		(1,551	)			(2,445	)			(3,451	)
Income before income taxes	$	5,183			$	13,377			$	12,232

 

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(1)	Corporate costs include the costs of running our corporate head office and other central functions that support the operating segments, including research, engineering and development, logistics, sales and marketing and health and safety and are not attributable to a particular operating segment.

 

 

Three months ended March 31, 2026 compared to three months ended December 31, 2025

 

NLA

 

Revenue for the NLA segment was $128.2 million for the three months ended March 31, 2026, a decrease of $2.1 million, or 1.6%, compared to $130.3 million for the three months ended December 31, 2025. The decrease was primarily driven by lower well flow management revenue in Guyana and reduced well construction revenue in the U.S. and Brazil, partially offset by higher subsea well access revenue in the U.S. and increased well flow management revenue in Mexico.

 

Segment EBITDA for the NLA segment was $25.9 million, or 20.2% of revenues, during the three months ended March 31, 2026, a decrease of $5.9 million, or 18.4%, compared to $31.8 million, or 24.4%, of revenues during the three months ended December 31, 2025. The decrease in Segment EBITDA and Segment EBITDA margin was primarily attributable to a decrease in revenue and less favorable activity mix. 

 

ESSA

 

Revenue for the ESSA segment was $113.9 million for the three months ended March 31, 2026, a decrease of $2.4 million, or 2.1%, compared to $116.3 million for the three months ended December 31, 2025. The decrease in revenue was primarily attributable to lower well flow management revenue in Angola and Bulgaria and lower subsea well access and well construction revenue in Ghana, partially offset by higher well construction revenue in Ivory Coast.

 

Segment EBITDA for the ESSA segment was $31.5 million, or 27.7% of revenues, for the three months ended March 31, 2026, a decrease of $8.5 million, or 21.3%, compared to $40.0 million, or 34.4% of revenues, for the three months ended December 31, 2025. The decrease in Segment EBITDA and Segment EBITDA margin, was primarily attributable to lower revenue and reduced work on higher margin projects.

 

MENA

 

Revenue for the MENA segment was $81.7 million for the three months ended March 31, 2026, a decrease of $11.3 million, or 12.2%, compared to $93.0 million for the three months ended December 31, 2025. The decrease in revenue was primarily driven by lower well flow management revenue in Algeria, Saudi Arabia, and Iraq, together with reduced well intervention activity in Qatar due to ongoing conflicts in the Middle East.

 

Segment EBITDA for the MENA segment was $23.6 million, or 28.9% of revenues, for the three months ended March 31, 2026, a decrease of $12.6 million, or 34.8%, compared to $36.1 million, or 38.8% of revenues, for the three months ended December 31, 2025. The decrease in Segment EBITDA and Segment EBITDA margin is consistent with the decrease in revenue and activity mix.

 

APAC

 

Revenue for the APAC segment was $43.8 million for the three months ended March 31, 2026, an increase of $1.3 million, or 3.0%, compared to $42.5 million for the three months ended December 31, 2025. The increase in revenue was primarily driven by higher subsea well access activity in Malaysia and increased Coretrax-related activity in Myanmar, partially offset by lower well flow management and subsea well access activity in Australia.

 

Segment EBITDA for the APAC segment was $7.2 million, or 16.4% of revenues, for the three months ended March 31, 2026, marginal increase of $0.2 million compared to $7.0 million, or 16.4% of revenues, for the three months ended December 31, 2025. The increase in Segment EBITDA is attributable primarily to increase in activity.

 

 

Depreciation and amortization expense

 

Depreciation and amortization expenses for the three months ended March 31, 2026 decreased by $8.4 million or 15.6%, to $45.4 million as compared to $53.8 million for the three months ended December 31, 2025. The decrease was primarily due to non-recurrence of $6.5 million of accelerated depreciation expenses related to subsea well access equipment.

 

Severance and other expense

 

Severance and other expenses was $3.2 million for the three months ended March 31, 2026, as compared to severance and other expenses of $10.0 million for the three months ended December 31, 2025. The decrease in severance and other expenses was primarily attributable to less restructuring activity across all segments.

 

 

Three months ended March 31, 2026 compared to three months ended March 31, 2025

 

NLA

 

Revenue for the NLA segment was $128.2 million for the three months ended March 31, 2026, a decrease of $6.1 million, or 4.5%, compared to $134.3 million for the three months ended March 31, 2025. The decrease was primarily attributable to lower subsea well access and well flow management revenue in the United States. These decreases were partially offset by higher well flow management and well construction activity in Mexico.

 

Segment EBITDA for the NLA segment was $25.9 million, or 20.2% of revenues, during the three months ended March 31, 2026, a decrease of $4.4 million, or 14.6%, compared to $30.4 million, or 22.6%, of revenues during the three months ended March 31, 2025. The decrease in Segment EBITDA and Segment EBITDA margin was primarily attributable to decrease in revenue and a less favorable activity mix.

 

ESSA

 

Revenue for the ESSA segment was $113.9 million for the three months ended March 31, 2026, slight increase of $1.5 million, or 1.4%, compared to $112.4 million for the three months ended March 31, 2025. The increase in revenue was primarily attributable to higher well construction activity in Angola and higher subsea well access activity in Ghana, partially offset by lower subsea well access revenue in Congo.

 

Segment EBITDA for the ESSA segment was $31.5 million, or 27.7% of revenues, for the three months ended March 31, 2026, an increase of $2.3 million, or 7.9%, compared to $29.2 million, or 26.0% of revenues, for the three months ended March 31, 2025. The increase in Segment EBITDA and Segment EBITDA margin, was primarily attributable to an increase in activities on higher margin services along with a slight increase in regular activities.

 

MENA

 

Revenue for the MENA segment was $81.7 million for the three months ended March 31, 2026, a decrease of $11.9 million, or 12.7%, compared to $93.6 million for the three months ended March 31, 2025. The decrease in revenue was primarily attributable to lower Coretrax-related activity in Saudi Arabia, well construction revenue in the United Arab Emirates and well intervention activities in Qatar.

 

Segment EBITDA for the MENA segment was $23.6 million, or 28.9% of revenues, for the three months ended March 31, 2026, a decrease of $10.6 million, or 31.0%, compared to $34.2 million, or 36.5% of revenues, for the three months ended March 31, 2025. The decrease in Segment EBITDA and Segment EBITDA margin was primarily due to less activities in the region and a less favorable mix.

 

APAC

 

Revenue for the APAC segment was $43.8 million for the three months ended March 31, 2026, a decrease of $6.9 million, or 13.5%, compared to $50.7 million for the three months ended March 31, 2025. The decrease in revenue was primarily driven by lower well flow management, subsea well access, and Coretrax-related activity in Australia, partially offset by higher Coretrax revenue in Myanmar, increased well construction activity in Brunei, and higher subsea well access revenue in the Philippines.

 

Segment EBITDA for the APAC segment was $7.2 million, or 16.4% of revenues, for the three months ended March 31, 2026, a decrease of $3.7 million or 33.8% compared to $10.9 million, or 21.4% of revenues, for the three months ended March 31, 2025. The decrease in Segment EBITDA is consistent with the decrease in revenue and decrease in activity on higher margin services.

 

 

Severance and other expense

 

Severance and other expense for the three months ended March 31, 2026 decreased by $2.9 million, or 47.0%, to $3.2 million as compared to $6.1 million for the three months ended March 31, 2025. The decrease in severance and other expense was primarily attributable to less restructuring activity across all segments.

 

Corporate costs

 

Corporate costs for the three months ended March 31, 2026 was $28.5 million as compared to $32.1 million for the three months ended March 31, 2025. The decrease is primarily attributable to cost savings initiatives and other cost reduction measures.

 

 

Liquidity and Capital Resources

 

Liquidity

 

Our financial objectives include the maintenance of sufficient liquidity, adequate financial resources and financial flexibility to fund our business. As of March 31, 2026, total available liquidity was $517.3 million, including $170.8 million of cash and cash equivalents and restricted cash and $346.5 million available for borrowings under our Facility Agreement (as defined below). Expro believes these amounts, along with cash generated by ongoing operations, will be sufficient to meet future business requirements for the next 12 months and beyond. Our primary sources of liquidity have been cash flows from operations. Our primary uses of capital have been for capital expenditures, acquisitions and repurchases of company stock. We monitor potential capital sources, including equity and debt financing, in order to meet our investment and liquidity requirements.

 

Our total capital expenditures are estimated to range between $85 million and $95 million for the remaining nine months of 2026. Our total capital expenditures were $25.8 million for the three months ended March 31, 2026, of which approximately 90% were used for the purchase and manufacture of equipment to directly support customer-related activities and approximately 10% for other property, plant and equipment, inclusive of software costs. The actual amount of capital expenditures for the purchase and manufacture of equipment may fluctuate based on market conditions. We continue to focus on preserving and protecting our strong balance sheet, optimizing utilization of our existing assets and, where practical, limiting new capital expenditures.

 

On October 30, 2025, the Company’s Board of Directors (the “Board”) approved a new stock repurchase program, pursuant to which the Company is authorized to acquire up to $100.0 million of its outstanding common stock from October 30, 2025 through December 31, 2026 (the “Stock Repurchase Program”). Under the Stock Repurchase Program, the Company may repurchase shares of the Company’s common stock in open market purchases, in privately negotiated transactions or otherwise. The Stock Repurchase Program will continue to be utilized at management’s discretion and in accordance with federal securities laws. The timing and actual numbers of shares repurchased will depend on a variety of factors including price, corporate requirements and the constraints specified in the Stock Repurchase Program along with general business and market conditions. The Stock Repurchase Program does not obligate the Company to repurchase any particular amount of common stock, and it could be modified, suspended or discontinued at any time. During the three months ended March 31, 2026, the Company repurchased approximately 1.2 million shares at an average price of $16.52 per share, for a total cost of approximately 20.0 million. During the three months ended March 31, 2025, the Company repurchased approximately 1.0 million shares at an average price of $10.08 per share, for a total cost of approximately $10.0 million.

 

Credit Facility

 

New Credit Facility

 

On July 23, 2025, the Company and certain of its subsidiaries, including Exploration and Production Services (Holdings) Limited and Expro Holdings U.S. Inc., as borrowers, entered into a senior secured revolving credit facility (the “New Credit Facility”) by and among, inter alia, DNB Bank ASA, London Branch, as agent, and other lenders, in an initial aggregate principal amount of up to $500 million, of which up to $400 million is available as revolving facility loans and up to $100 million is available as term bridge loans. Proceeds of the revolving facility under the Facility Agreement may be used for general corporate and working capital purposes. Proceeds of the bridge facility under the Facility Agreement may be used for acquisitions and investments and capital expenditure in relation to acquisitions and fees, costs and expenses in connection with the foregoing. The Facility Agreement replaces the Company’s prior senior secured revolving credit facility entered into on October 1, 2021 and as amended and restated pursuant to an amendment and restatement agreement on October 6, 2023 (the “Prior Facility Agreement”). The maturity date of the New Credit Facility is July 30, 2029. 

 

As of March 31, 2026, we had $79.1 million of long-term borrowings outstanding under the New Credit Facility.

 

Please see Note 16 “Interest bearing loans” in the Notes to the Unaudited Condensed Consolidated Financial Statements for additional information.

 

 

Cash flow from operating, investing and financing activities

 

Cash flows from our operations, investing and financing activities are summarized below (in thousands):

 

	Three Months Ended
	March 31, 2026				March 31, 2025
Net cash provided by operating activities	$	25,284			$